eor - the development of heavy oil fields in the u.k. continental

Copyright 1999, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 1999 SPE Western Regional Meeting held inAnchorage, Alaska, 26–28 May 1999.

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AbstractHistorically, most UKCS production has been of light oil, 300

API and above. However, since 1993, a number of heavy oilfields have been brought on production. This paper reviews thehistory of UKCS heavy oil, the challenges overcome to bringthese fields to development, and the future outlook.

The occurrence and distribution of the UKCS heavy oil inplace is discussed. A specific correlation to estimate reservoirviscosity from API gravity is presented. Productivity of heavyoil reservoirs is compared with light oil developments,different categories of heavy oil reservoirs are identified, andthe use of horizontal or multilateral well technology to achieveacceptable production rates is discussed. The implication ofwell productivity testing (e.g. extended well testing) ofappraisal wells is discussed.

The development challenges that have been overcome incurrent developments (Harding, Gryphon, Alba, Captain) arereviewed, in particular focusing on well productivity, pressuresupport, recovery efficiency (management of gas and waterconing, areal sweep), and oil water separation. The paper willalso review the cost and risk management strategies that needto be adopted to enable the economic exploitation of theseheavy oil resources in a demanding environment such as theUKCS.

Finally, the potential for future heavy oil developments isdiscussed. The scope for IOR technology to increase reservesin heavy oil fields on production by waterflood, or to improvethe economics of currently sub-economic fields, is reviewed,focusing on advanced well technology, downhole separation,thermal techniques and conformance control methods.

IntroductionEarly production from UKCS oil fields has been of light oil.However, a significant number of “heavy” oil fields have alsobeen discovered, which, in the context of this paper, is taken torefer to reservoirs with in-situ viscosities greater than 5 cp. Themajority of UKCS heavy oil occurs in relatively shallowreservoirs, comprising high porosity unconsolidated sands withexcellent horizontal permeability (typically 3,000 to 10,000md) and very high vertical permeability (kv:kh in the range 0.2to 1.0). The oil columns are usually at least partially underlainby water and some also have primary gas caps.

This combination of reservoir parameters and thedemanding offshore environment of the UKCS, presents aspecial set of reservoir engineering challenges, because of thedifficulties in achieving and maintaining sufficiently highproduction rates to justify development. This paper providesan overview of the development of heavy oil fields on theUKCS, past, present and future, with an emphasis on the sub-surface issues. This shows how the application of newtechnology, principally horizontal wells, extended reachdrilling and improvements in sand control has led to successfuldevelopments. Increasing confidence in this technology hasallowed the Captain field (reservoir viscosity 88 cp) to bebrought on to production and encouraged appraisal activity onother fields with viscosities as high as 1000 cp.

It is conservatively estimated that there are around 10billion STB of heavy oil in place on the UKCS. Less than aquarter of this resource is currently being developed.Assuming that recovery factors for the undeveloped STOIIPare likely to be in the range 20 to 40 %, shows that there areapproximately 1.5 to 3 billion barrels of additional reserves tobe produced, which will make a significant contribution to thelongevity of the UKCS.

Heavy Oil Resources in the UKCSHeavy oil production first took place on the UK mainland inthe late 18th century. This was in Ironbridge, Shropshire,where heavy oil from the Carboniferous was produced throughseepage into mine shafts. With the onset of oil exploration inthe North Sea it was inevitable that some oils that fall into theheavy oil category, would be discovered. Many of the heavyoil accumulations discovered in the UKCS are in the Northern

SPE 54623

The Development of Heavy Oil Fields in the U.K. Continental Shelf:Past, Present and FutureA J Jayasekera, SPE, United Kingdom Department of Trade and Industry, S G Goodyear, SPE, AEA Technology

2 A J JAYASEKERA and S G GOODYEAR SPE 54623

North Sea, in the eastern margins of the East ShetlandPlatform. Other significant discoveries are in the FladenGround Spur, the Halibut Horst, and west of the CentralGraben. Heavy oils have also been discovered in the Atlanticmargin area. Fig. 1 shows the structural elements in the Centraland Northern North Sea and the location of producing heavyoil fields and those currently being actively appraised.

The majority of heavy oil discovered to date occurs in theLower Tertiary. Fig. 2 shows the conceptual chrono-stratigraphy of the important Lower Tertiary sand reservoirs.The main heavy oil reservoirs are in the Upper PalaeoceneMaureen Formation, the Heimdal sands in the Lista formation(e.g. Mariner), and the Dornach and Hermod sands in the Seleformation (e.g. Bressay), the Balder and Frigg sands (e.g.Gryphon and Harding) and the mid-Eocene Nauchlan sand(Alba). The Captain field, which was discovered in 1977, is inthe Lower Cretaceous Captain sand, and has the lowest API oiland highest in-situ oil viscosity of any currently producingUKCS field.

The source rock for all the heavy oil fields in the UKCS isthought to be the Jurassic Kimmeridge clay. The oilsoriginated from the deeper Central Graben and migratedwestward and up the prominent faults which bounded thegraben area, into traps in younger rock, in the shelf areas.Washing by meteoric water during the migration of the oilthrough the long tortuous paths caused a reduction in the APIgravity. However, the main cause of the low gravity is thoughtto be due to biodegradation. At shallower depths, and lowertemperatures, the bacterial activity becomes more and moreintense, giving heavier oils, resulting from the removal oflower molecular weight alkanes. A plot of reservoir depthversus API gravity for some typical North Sea discoveries withAPI gravity less than 25o from the Shetland Platform andFladen Ground Spur is shown in Fig. 3. Some of these heavyoil fields have gas caps, probably as a result of thebiodegradation process or a late gas charge.

Table 1 shows a summary of the oil accumulations in theUKCS that fall into the ‘heavy oil’ category. It can be seen thatover 2.1 billion barrels of oil-in-place are being developed.Three fields, Clair, Mariner and Bressay have been activelyappraised over the last few years. The total developable oil-in-place in these is around 2.7 billion barrels. Clair is differentfrom the other heavy oil plays in that it is in a much olderDevonian formation, having a very complex geology. Themapped oil-in-place in Clair is some 5.4 billion barrels,however only a more limited volume of oil in the “core” area isthought to be developable. All the other discoveries total up toaround 2.4 billion barrels. Other undrilled prospects in blocksstudied to date, would add a further 2 billion barrels or so. Thiswould imply that a conservative total heavy oil in-placeestimate for the UKCS is around 10 billion barrels. Blocks notworked on as yet can be expected to add to this total.

Table 2 shows a summary of the typical characteristicsseen in the UKCS heavy oils, giving an indication of theirmarketability.

API and Reservoir ViscosityCrude oils are usually characterised by their API oil gravity (ameasure of surface density). However, the API gravity of theoil is not necessarily an indicator of its producibility, sincefrom a sub-surface standpoint it is the oil viscosity, and to alesser extent the density, at reservoir temperature and pressurethat are the key fluid properties. Reservoir temperature and theGOR have a very significant influence on the viscosity of thelive oil, so that oils with a similar API gravity can have verydifferent viscosities in the reservoir. A low API oil at a deeperhorizon may be easily producible, on account of its lower in-situ viscosity. A 10oF increase in reservoir temperature canresult in an order of magnitude reduction in viscosity in thecase of high viscosity oils.

The data in Fig. 3 has been analysed using viscositycorrelations to infer information about reservoir viscosities.Many of the available correlations for dead oil viscosity havebeen based primarily on North American crudes. Recently anew heavy oil viscosity correlation has been published1, usingdata from selected North Sea viscous oil reservoirs. Thecorrelation gives dead oil viscosity as a function oftemperature and API according to:

µodxAPI T xAPI= − + −10 8021 238765 0 31458 9 21592( . . ) . ( . . ) . ....(1)

By including data from further samples the correlation couldbe extended by using the Watson characterisation factor, as ameans of adjusting the predicted viscosity depending on thedegree of paraffinicity of the sample.

Fig. 4 shows the estimated viscosities of dead oil atreservoir temperatures as a function of API, corresponding tothe data in Fig. 3. This shows that, for a given API, quite awide range of viscosities (at least a factor of 10) can beencountered depending on the depth of the reservoir. Inaddition, dissolved gas will have the effect of reducing the in-situ viscosity, with saturated oil viscosities typically being afactor of 3 to 6 lower than the corresponding dead oil. Thisdiscussion highlights the importance of good measurements ofreservoir temperature and GOR. In the more viscous oilreservoirs it can be difficult to obtain reliable measurements ofGOR from vertical appraisal wells. The high drawdownsneeded to achieve acceptable production rates may make ithard to collect good single-phase downhole samples, and theseparation problems associated with heavy oils may makeaccurate surface measurements of GOR from short term testsdifficult. In some cases, a horizontal appraisal well operating atlow drawdowns may be needed to obtain sufficiently accuratedata.

Reservoir ProductivityThe basic productivity of a reservoir will be controlled by thereservoir geometry (primarily formation thickness andreservoir continuity) and the ratio of the permeability of theformation to the viscosity of the oil. As a first approximation,combinations of permeability-thickness and viscosity in the

SPE 54623 THE DEVELOPMENT OF HEAVY OIL FIELDS IN THE U.K. CONTINENTAL SHELF: PAST, PRESENT AND FUTURE 3

same ratio will correspond to equivalent reservoirproductivities.

Combinations of permeability-thickness and viscositygiving the same productivity are illustrated by the lines on Fig.5. Data points are included from major first generation light oilfields, together with some of the recent viscous oildevelopments and fields under appraisal. From this it can beseen that many of the current viscous oil developments havesimilar productivity to existing light oil developments, becausethe fields have very high permeabilities that compensate for theincreased viscosity. The primary reservoir development issuein these situations is the control of premature water or gasbreakthrough through the use of horizontal wells. In contrast,the Captain and Gannet E developments are significantly morechallenging, with a productivity index an order of magnitudelower than the other viscous oil fields under development,requiring the issue of productivity and sweep to be addressedto achieve a robust development plan.

Vertical and Horizontal Wells. Fig. 5 highlights thatreservoir productivity may be a key challenge that needs to beaddressed. Many of the UKCS viscous oil fields are in highpermeability unconsolidated sands, with very high verticalpermeability across the full reservoir interval, (typicallykv:kh>0.1), making them good candidates for the application ofhorizontal well technology.

The flow rate for a well in STB/day can be expressed in theform:

Qk h

BJ ph

o o=

µ* ∆ . ...............................................................(2)

where the productivity index, J*, is in units of bbl.cp/(day.psi.

md ft). For a vertical well with no skin this is given simply by:

J r re w* . / ln( / )= 0 007078 . .......... ......................................(3)

while for a horizontal well J* is a more complicated function,involving the vertical to horizontal permeability ratio, reservoirthickness, well length, well radius and drainage area. Renardand Dupuy have derived an equation to estimate J* for ahorizontal well2. As an example, Fig. 6 compares theproductivity coefficient for a vertical well and different lengthhorizontal wells in formations with thicknesses of 50, 100, 150and 200 ft, for a well with a drainage area of 140 acres (with acircular drainage area for the vertical well and an ellipticalregion for the horizontal well), a kv:kh of 0.5 and a well boreradius of 0.25 ft. For long horizontal wells theoreticalproductivity enhancements up to a factor of 30 are predicted,compared to the vertical well productivity coefficient. In lowproductivity reservoirs, the use of horizontal wells candramatically reduce the number of wells required to meet theinitial oil plateau rate. For example, in the Captain field at least50 vertical wells would be required to obtain the plateau rateof 60,000 BOPD, compared to 5 horizontal producers.

Taking 10,000 bbl/day as the oil rate required from a singlewell in a typical development scenario, and assuming a

maximum drawdown of 250 psi (taking into account therelatively shallow unconsolidated nature of the viscous oilreservoirs and the fact that many contain saturated oils), usingthe results of Fig. 6 shows that with vertical wells the reservoirkhh/µo needs to exceed approximately 50,000 md.ft/cp(assuming Bo is near 1 for viscous oil fields). Where longhorizontal wells are deployed (6000 ft) the minimum khh/µo

falls to approximately 5,000 md.ft/cp, (taking a productivityindex enhancement of 10 compared to vertical wells,recognising that the inflow profile may not be uniform becauseof wellbore friction). These approximate limits for theapplication of different well technology are shown in Fig. 5.This highlights three categories of viscous oil reservoir from aproductivity standpoint: those that can be developed withvertical wells, those requiring horizontal wells and thoserequiring even larger completion lengths through theapplication of multi-lateral well (MLW) technology or veryclosely spaced horizontal wells.

The low productivity of the more viscous reservoirs meansthat wells may not flow under test without artificial lift.

Case Histories - Fields in ProductionIn this section the focus is on the UKCS heavy oil fields thatare currently in production, to try and highlight the areas wherelessons have been learnt, and the ways in which costs and riskshave been managed. As seen in Table 1, the heavy oil fields inthe UKCS that have proceeded to development so far, arethose having in-situ oil viscosity below about 20 cp, except inthe case of Captain, which has an in-situ oil viscosity of about88 cp.

In the early days, when these heavy oil plays were beingdiscovered and appraised, the wells were vertical, or at amoderate angle to the vertical. In most cases, high enough oilrates could not be achieved and sustained for long enough tojustify commercial development. The key impetus to theexploitation of these heavy oil reserves can be attributed to theadvances made in horizontal drilling. Horizontal completionswill minimise pressure drawdown and maximise stand-off fromthe oil/water contact, thus achieving much higherproductivities compared to a vertical well. These reservoirs arerelatively shallow, hence exceptionally high offset/TVD ratiosneed to be achieved. The extremely high vertical permeabilityin these sands makes the onset of water coning into thehorizontal wellbore one of the key criteria in the well design.The well track needs to be as close to the top of the reservoiras possible, to optimise recovery. If there is a gas cap as well,then an optimal stand-off from the gas cap needs to bemaintained. Measurement while drilling, and modern wellsteering techniques, make the siting of horizontal wells, to therequired tolerances, possible. Wells with stepout, from thedrilling centre, of up to 13,000 ft and horizontal sections goingup to 6000 ft in length, have been utilised in these fields.

Due to the unconsolidated nature of these formations, sandcontrol measures are essential in the design of the completionsin the production and water injection wells. The commonly


used completions have pre-packed screens for sand exclusion.Other methods, such as gravel packs with wire wrappedscreens, have also been used.

Waterflooding is the main recovery method. On account ofthe adverse mobility ratio, water breakthrough occurs early,and a large portion of the reserves will be recovered at highwatercut. Full voidage replacement, by injecting water into theaquifer, is implemented right at the outset, to maintainreservoir pressure and hence the lift capability in the producingwells. It is particularly important in the case of reservoirs withgas caps, to prevent the expansion of the gas cap towards theproducing wells. All these fields need some form of artificiallift to maintain sufficiently high production rates. This couldbe in the form of ESPs, hydraulic pumps or gas lift. Permanentbottomhole pressure gauges are usual for these wells,especially if ESPs are used. This is mainly to optimise ESPperformance, but also to provide pressure data for reservoirmonitoring purposes.

As these fields produce large quantities of water, and theseparation of water from the relatively heavy crude is notstraightforward, considerable uncertainties will be inherent inthe design of the process equipment, and the selection of theappropriate chemicals for de-emulsification, de-foaming andso on. The ultimate bottom line is that the export crude has tobe within the specified water content limit, and the producedwater needs to be de-oiled to less than 40 ppm oil content. Theoil/water separation process may be simulated in a flow loop inthe laboratory, if a sufficiently large oil sample is available. Anextended well test (EWT) in an appraisal well will provide anopportunity to test out the process design and equipment.

Development risks will be significantly reduced if the longterm productivity, and the water production (and gas coning, ifapplicable) behaviour is tested by conducting an EWT with aprototype field development well, prior to the developmentdecision. The results of such a test can be used to confirm oradjust the reservoir parameters used in the simulation model,such as kv:kh, relative permeability characteristics and so on. Aprototype production well at the appraisal stage would alsoenhance drilling experience and highlight any drilling risksinvolved in siting long horizontal wells to tight tolerances. AnEWT is usually over a three month period. This length oftesting would be sufficient to test and optimise the processfacilities, and to evaluate the performance of the ESP and thegas lift option, and the performance of the completion. If waterhas not broken through during this time, it is usual to injectsimulated formation brine, using coiled tubing, to simulatewater coning to clarify separation issues. Lastly, the quantity ofoil collected during an EWT could be used to test out itsmarketability, and of course, to try and recover all or part ofthe cost of the test.

In the development scheme that is selected, the costs andrisks may be managed by proceeding in a phased manner. Thephilosophy is to avoid loading too much capital expenditure upfront, and to ensure sufficient cashflow from the first phasebefore committing to expenditure on the next, and so on. The

following brief descriptions of some producing UKCS heavyoil fields should provide a flavour for the types of philosophiesthat have been adopted:

Harding.3,4 The field consists of four stratigraphically separatepools, Harding Central, Harding South, Harding North andHarding Northeast. The Development Plan initially commits todeveloping the Central and South pools, containing a totalstock tank oil initially in place (STOIIP) of 322 MMSTB. Fig.7 shows the top structure map of these two pools. The mainreservoir sands, in the Eocene Balder formation, are extremelyhomogeneous, having very high porosity and permeability.Both accumulations have gas caps. However, the gas caps areoffset towards the east, as shown by the cross section in Fig. 8.Thus some producing wells can be sited to avoid gas coning.In general, to delay the onset of gas breakthrough, thehorizontal production wells are completed with an optimalstand-off of some 75 ft from the GOC. The PI of eachhorizontal well is estimated to be in excess of 1000 BOPD/psi,implying that the drawdown in a typical well will be just 10psi.

The two pools are developed using ten horizontalproduction wells, three water injection wells, and one gasinjection well in Harding Central - all drilled from one drillinglocation that is central to both pools. In addition, two watersupply wells are drilled into an aquifer in a shallowerformation. This is because there is a risk of severe scalingproblems, due to Barium Sulphate deposition, if seawater isused for injection. Produced water will be re-injected aftertreatment. The excess gas is injected into the Harding Centralgas cap for future offtake. The development facilities are basedon a permanently installed heavy duty jackup platform, withproduction and drilling facilities. The jackup sits on a concretebase, which also contains storage tanks for oil. The facilitiescan handle a peak production rate of 85,000 BOPD, and up to140,000 BWPD of produced water. Oil export is by tankers.

The main impetus that pushed this development forwardwas the success with the 1000 ft horizontal appraisal welldrilled and tested with an EWT in 1991. This confirmed thefeasibility of developing Harding Central and South usinghorizontal wells, drilled from a central location. Harding beganproduction in April 1996.Gryphon.5 This field is in effect a sister field to Harding,being in the same locality and in the same formation, andhaving similar reservoir characteristics, including the presenceof a gas cap. As such, the success of the Harding horizontalappraisal well was of benefit to Gryphon too. As in Harding,the development scheme for Gryphon depends largely uponhorizontal wells. A total of eight horizontal producers, threewater injection wells, and two aquifer supply wells, all drilledfrom a subsea wellhead cluster location, are utilised.

The field is produced through a purpose built floatingproduction and storage and offloading facility (FPSO) basedon the Tentech 850C design. It has 60,000 BOPD oil capacity,77,000 BWPD produced water handling capacity and 79,000


BWPD water injection capacity. The low abandonment costsand the resale value of the FPSO significantly improve theeconomics of this development. Gryphon began production inOctober 1993. It demonstrated the feasibility of using lowsulphate aquifer water for injection.

Alba.6,7 The reservoir consists of a stratigraphic trap where themid Eocene Nauchlan sands, up to 400 ft thick, are sealed onall sides by shales. The STOIIP is estimated at greater than500 MMSTB. The system has a limited aquifer, having a porevolume similar to that of the oil zone, with the water legincreasing in thickness towards the south. The Nauchlan sandsare generally clean and have high permeability. However,interbedded allochthonous shales have been encountered inseveral wells. These are thought to be 'stringer' shales, and arenot expected to effect recovery, but impact the drilling ofhorizontal wells, making a sidetrack necessary if the well pathgoes through too much of it.

The total well count as currently planned, has 24 producersand 7 water injectors. Alba has no gas cap. Hence, the optimalplacement of the horizontal wellbore is close to the top of thereservoir, away from the OWC. MWD and wellsitebiostratigraphy have helped in achieving the optimal trajectoryin these wells. The water injectors are completed in the waterleg at the base of the reservoir, and the recovery mechanism isexpected to be an efficient, bottom up, water drive. Fullvoidage replacement is being implemented to maintainreservoir pressure. Artificial lift will be by installing ESPs inall the producers. The injection water is seawater, and theproduced water is not re-injected.

The main uncertainties in Alba were the mapping of theNauchlan sands, and hence the STOIIP, and predicting thewatercut behaviour and hence oil rates. The latter wouldimpact on the sizing of the separators and process equipment.The original plan had a platform (drilling, processing,accommodation) in the north of the field to develop the 'corearea', during phase 1. This was to be followed by a second,similar, platform some 6 km to the south, in the second phase.Operating experience and reservoir performance from phase 1was vital for the optimisation of phase 2. With ERD wells it ispossible to reach all of the southern producing well locations,obviating the need for the southern platform. By retrofittingadditional processing equipment on the northern platform, it ispossible to handle the total liquid handling requirements. Theupgraded capacities are 100,000 BOPD (continuous) for oil,390,000 B/D for gross liquids and 400,000 BWPD waterinjection.

Gannet E. The reservoir consists of a low relief anticline inthe Palaeocene Forties formation, with around 225 ft of grossoil column. The sand is of excellent quality. Gannet E is one ofthe Gannet cluster of accumulations (A, B, C, D, E, F), whichhave the central processing facilities (Gannet Alpha) located atGannet A. Gannet E is a more recent add-on to the complex,

and it is the only one with heavy oil. Gannet E production isexported through the existing Gannet evacuation system.

The field is developed as a subsea tie-back to GannetAlpha, which is 14 km away. Due to the high viscosity of theoil it is a significant technological challenge to develop GannetE in a cost effective manner. The development is in twophases. Phase 1, which is currently ongoing, has one 2800 fthorizontal well. It has a pre-packed screen in the completion,and an ESP to provide lift. It is the first subsea development inthe UKCS to use ESP technology. The expectation is thatwater injection will not be required, as the large regionalForties aquifer would provide a strong natural water drive.Operational experience from phase 1 will be essential to betterdefine phase 2, which may require a further two or morehorizontal producers. In addition to the reservoir uncertainties,operational uncertainties such as the performance of the ESP,how the separators at Gannet Alpha will handle the heavycrude, and how the high viscosity emulsions that will beproduced when water production commences, are going to behandled, need to be fully assessed.

Captain.8 This field falls into a different class from the aboveas the in-situ oil viscosity is much higher and the waterfloodrecovery is affected much more by the adverse mobility ratio.The reservoir is in unconsolidated lower Cretaceous, highporosity, high permeability sandstone. Fig. 9 shows thehydrocarbon accumulation map of the field. The developmentscheme has to be based on horizontal producing wells. Thereservoir depth is relatively shallow at 2900 ft TVDSS. Toexploit all of the field, wells have to be drilled from twodrilling centres.

An EWT with a prototype horizontal well was conductedsuccessfully in 1993, prior to the development decision9. Theresults of this significantly reduced the development risks. Itwas decided to go for a staged development to minimise initialcapital investment and to gain valuable operational experience,prior to the next phase. The initial development area is denotedas area A in Fig. 9. The first phase, installed in January 1997,consists of a FPSO and a wellhead platform at the area Adrilling centre. The FPSO is capable of processing 65,000BOPD oil and 230,000 BWPD produced water. The producedwater is re-injected, along with make up water from anunderlying aquifer.

The second phase of the development is to access thereservoir in eastern area B. For this phase the capacity of theproduction facilities need to be upgraded to 100,000 BOPD oiland 400,000 BWPD produced water. The scheme to achievethis is to install additional processing capacity on a newplatform, bridge linked to the area A wellhead platform, andaccess area B by drilling wells from a subsea centre, with aflowline bringing the commingled flow to the area Aprocessing facilities.

According to the current simulation model, area A willneed 21 producing wells and 6 water injectors, and area B willneed 12 producing wells and 3 water injectors, during the life


of the field. Fig. 10 is a cross section showing a typicalhorizontal producing well in Captain. It shows the severalsidetracks that were necessary to keep the well track close tothe top of the reservoir. Horizontal lengths in excess of 6000 fthave been achieved in some these wells. Area A producingwells have ESPs for artificial lift, while hydraulic submersiblepumps are planned for area B. Oil rates of 15,000 BOPD havebeen achieved in some of these wells, and gross fluid rates upto 21,000 B/D.

The use of polymers to augment the waterflood has beenactively evaluated for Captain10. A pilot scheme for a localisedarea is being considered. The final go ahead for this will ofcourse depend on the prevailing economics.

Case Histories - Fields in the Appraisal StageThere are many UKCS heavy oil fields that are still underappraisal, the most prominent being Clair, Mariner andBressay. These have been worked fairly actively, until aroundmid-1998, when the slump in the price of oil began to have anegative impact on the economics driving new developments.However, to complete the story on the development of heavyoils in the UKCS, and to perhaps provide some clues as to thepossible future of these heavy oils, it would be appropriate toprovide some description of the work that has been done toevaluate these fields.

The key criterion that would propel any of these fields to adevelopment phase is positive economics with a primary or acold waterflood recovery scheme, even though recoveryfactors may not be high. While waterflooding is extensivelyused in the offshore environment in the UKCS, and the risksare well understood, there is very limited offshore experienceof more advanced methods, such as thermal processes forviscosity reduction, or chemical methods such as polymerinjection for improving conformance. To manage risk thesewill have to be subsequent 'add-ons' to the baseline coldwaterflood scheme, if the IOR scheme is shown to besuccessful via a pilot project. The Captain field will provide agood example of this, if the polymer pilot goes ahead.

As stated earlier, Clair11 is in an older (Devonian) anddeeper formation. The sands have a much lower permeability,and achieving economic flowrates depends on naturalfractures, or artificial stimulation, even with horizontal wells.As such, Clair belongs in a category of its own, and will not beelaborated any further in this paper.

Mariner. This field has two Palaeocene hydrocarbon bearingzones. The upper reservoir is in the Heimdal sand, having avery heavy 540 cp in situ viscosity oil. The lower reservoir isin the Maureen sand, with 65 cp oil, and underlain by a largeaquifer. Neither reservoir has a gas cap. Fig. 11 shows a logcross section containing these two horizons.

The Maureen reservoir was being considered for the firstphase of a development scheme, as reasonable flowrates andrecoveries could be achieved by a cold waterflood. Simulationstudies have investigated schemes that utilise long horizontal

wells (6000 ft) or multilateral wells (3000 ft). The economicsof drilling long, large diameter horizontal wells at such shallowdepths brings such schemes into serious consideration. Most ofthe oil is recovered at high watercut. Plateau oil rate of 60,000BOPD and total liquid production rates of up to around350,000 B/D are assumed. The operator also had studiesperformed to investigate thermal methods for Maureen, butthese were found to be uneconomic due to the large underlyingaquifer.

A 90 day EWT was conducted using a prototypedevelopment well. It is worth mentioning that the drilling ofthis well pushed drilling and completion technology into newareas. One was the drilling of 5749 ft of 12 1/4’’ horizontalhole entirely in the Maureen reservoir. However, plugging ofthe 9 5/8’’ pre-packed screens limited production rates and,subsequently, an 8 1/2’’ sidetrack was drilled, having 4004 ft ofhorizontal section in the Maureen. This was completed with 51/2’’ screens and subsequently externally gravel packed. A30,000 B/D ESP, with variable speed drive was used. TheEWT was a success, yielding valuable experience in drilling,completion, production and processing. Elaborating anyfurther on this will be beyond the scope of this paper.

The overlying Heimdal reservoir was intended to bedeveloped in a subsequent phase. The key uncertainty inHeimdal is the mapping of the sand, primarily due to the poorseismic imaging of the Heimdal sequence. The furtherappraisal of Heimdal could proceed 'piggy back' with thedevelopment of Maureen, perhaps using the same wells.

The operator has had several studies performed toinvestigate thermal methods for Heimdal. These were steamand hot water flooding, and steam assisted gravity drainage(SAGD). SAGD is the most operationally complex, but yieldshigh recoveries. The success of a SAGD process for Heimdalhowever depends on the presence and size of connectedaquifer.

Bressay. This field has the heaviest oil (110-120 API, 1000 cpin situ oil viscosity) of all the fields discussed so far. It is in theHermod and Dornoch sands in the Sele formation, with about265 ft maximum oil column, a small gas cap, and a potentiallylarge and effective aquifer. Fig. 12 shows the top structuremap. The permeability is in the 10 darcy range. Fourconventional appraisal wells have been drilled in theformation. DSTs conducted in these, with ESPs for artificiallift, had flowrates ranging from 200 to 2800 BOPD.

The thrust has been to demonstrate that an economicdevelopment can be achieved with a cold water flood as thebaseline scheme. Simulation studies have considered long(6000 ft) horizontal wells, bilateral wells and trilateral wells,with water injection to ensure 100 % voidage replacementfrom the outset. Well spacings from 30 to 60 acres have beentried. It has been highlighted that the frictional losses along thelong horizontal wellbore is a factor to consider in the design ofthe scheme. A further appraisal well or two need to be drilled,and an EWT, on similar lines to those conducted in the fields


discussed above, needs to be carried out, before sufficientconfidence can be gained, to proceed to a development.

A range of tertiary recovery techniques have beensimulated with Bressay. These are the injection of polymer, hotwater injection, gas injection, steam injection and in-situcombustion. Steam injection gave the highest recovery, whilein-situ combustion came next.

IOR TechniquesThis section discusses the scope for application of IORtechniques to overcome some of the problems caused by lowproductivity and poor sweep. The technical and economicviability of IOR methods needs to be carefully examined on acase by case basis.

Multilateral Wells. The application of multi-lateral welltechnology could reduce the number of wells required in verylow productivity fields, increasing the economic viability ofthese developments. However, a key requirement for thesuccessful application of MLW technology is the capability tocontrol the offtake rate from individual laterals. Without this,the lower drawdowns required to achieve a given flow rate aswater breaks through, would mean that an increasing volumeof fluid would be produced from the first lateral cutting water,at the expense of the other laterals. The option of completelyshutting off the offending lateral would not be acceptable,since a significant fraction of the recoverable reserves areproduced after water breakthrough, with wells typicallyneeding to produce for extended periods at high water cuts.

Downhole Separation. Downhole separation with the disposalof water downhole can improve oil recovery in circumstanceswhere production is facilities constrained. Hydrocyclones areused to separate off a purified water stream and downholepumps to provide the power to produce fluids to surface and topump excess water into a disposal zone.

In viscous oil applications separation difficulties may arisebecause of the small density difference between the oil andwater and because high bulk fluid viscosities can arise throughthe formation of emulsions at intermediate volume fractions ofoil and water. The high viscosities constrain the practical rangeover which concentration of the oil in the produced fluid ispossible. However, even removing half the water downholefrom a well producing at 90% watercut allows increased oilproduction (with the watercut decreased to 82%). Thereduction in fluid production to surface provides an alternativeto expanding the existing free water knockout capacity,however this is at the cost of installing more complexequipment downhole and providing an appropriate waterdisposal route in each well.

Polymer Flooding. Where waterflood displacements areviscous dominated the reservoirs are potential targets for theclassical application of polymer flooding to reduce the localeffective residual oil saturation by changing the fractional flow

curve and to improve sweep in less permeable zones.However, polymer flooding can also be effective in gravitydominated viscous oil reservoirs12. In the absence ofunderlying water, injected water slumps and channels along thebase of the reservoir before coning into the producer. Inpolymer flooding, the ratio of viscous to gravity forces isincreased, reducing the slumping and improving vertical sweepin the reservoir. Even in the presence of an underlying aquifer(provided the thickness is no greater than the thickness of theoil column), polymer flooding can still be effective, byrestricting water channelling through the aquifer.

The viscous oil reservoirs are shallow enough for thetemperature to be low enough for biopolymers to havesufficient thermal stability to be applicable. The best candidatefor polymer flooding identified to date is Captain. The lowformation water salinity and hardness makes polyacrylamide(PAM) injection feasible. This has logistical advantages sincePAM can be delivered to the platform in the form of highconcentration liquid emulsions or dispersion products. From asub-surface standpoint, PAM has the advantage compared tobiopolymers of producing a residual resistance factor (RRF)associated with adsorbed polymer. This can provide a longterm reduction in permeability in flooded zones after themobile polymer has been swept through the reservoir, furtherincreasing recovery. The presence of an RRF is particularlybeneficial in regions of the reservoir underlain by water.

Gas Injection. Gas injection into a primary gas cap, where thisexists, may provide an alternative strategy to water flooding,giving lower effective residual oil saturations (because of themuch greater density contrast between oil and gas compared tothat between water and oil). Recent measurements13 of oilgravity drainage relative permeabilities in sandpacks withpermeabilities representative of UKCS viscous oil fields, haveshown that relative permeabilities are independent of viscosityover the range 2 to 200 cp and higher than those found inconsolidated outcrop sandstone. The effective residual oilsaturation over a range of viscosities and injection rates havebeen calculated, under appropriate conditions effectivesaturations of ~10% may be obtained for oils of 100 cp.

Thermal Methods. Increasing temperature can significantlyreduce the oil viscosity. This section discusses the potential forthermal methods, recognising the limitations that offshoreoperations might place on project feasibility.

Hot water flooding. Even if specific hot water injectionfacilities are not provided on the platform, hot water may beavailable as a by-product of the separation process. Thedisplacement mechanisms associated with hot water floodingare complex, with even the density difference betweenreservoir brine and the injected hot water being important insome circumstances14. A potential problem with hot waterflooding is the unstable nature of the displacement, triggeredby the unstable miscible displacement between cold and hot


water15. Studies of the potential for hot water flooding toimprove recovery have been undertaken for a range of fields16:

For moderate temperature fields with oil viscosities around10 cp (e.g. Alba, Gryphon and Harding), hot water floodingmakes little difference to recovery in the absence of underlyingwater, but reduces recovery in the presence of limitedthicknesses of underlying water12.

Studies in Captain (typical of low temperature fields withoil viscosities around 100 cp) suggested that there was nosignificant benefit from hot water flooding. Depending on thedetails of the scenario considered (e.g. production rate, kv:kh)there could be a marginal benefit (+0.7% STOIIP) to a smallreduction in recovery (-2.6% STOIIP). In cases where anincrement was found, there was a long delay between the startof the hot water injection and the production of incrementaloil.

Conceptual studies relevant to low temperature fields withhigher viscosities (~400 cp) and where the oil column isunderlain by a thick aquifer, have shown systematic benefitsfrom hot water flooding, up to 18% STOIIP. However, theresults were very sensitive to kv:kh, which in turn impacts onthe optimal position for the hot water injector.

Steam Injection. Steam injection is a highly successfulIOR method for onshore shallow heavy oil fields. Given thedepth of the higher viscosity UKCS viscous oil fields (3000-5000 ft), steam flooding is only likely to be economicallyfeasible if the reservoir pressure is significantly reduced priorto steam injection. This rules out reservoirs with significantaquifer pressure support as candidates.

Simulation studies in typical pattern elements show thatsteam flooding has the potential to double recovery comparedto water flooding, provided gravity forces are utilised tocontrol the steam front. This means operating in a SAGD typemode, or by injecting steam into a depleted primary gas cap,where this is present, and using horizontal production wellsplaced low in the oil column.

Even if the facilities issues associated with offshore steamgeneration and injection can be overcome, it may be difficultto implement a steam flood, since the well positions requiredfor a basic water flood may be quite different from thoseneeded for a steam flood.

In-situ Combustion. Air injection provides an alternativeto hydrocarbon gas or nitrogen injection, with potentialbenefits from reduced gas costs and lowered effective residualoil saturations. The same overall considerations relevant to gasinjection apply, with additional concerns including the effectof breakthrough of corrosive combustion products on theproduction facilities and well casing integrity in thecombustion zone.

Future Directions for UKCS Heavy Oil DevelopmentsIt is fortunate that UKCS heavy oils generally occur in theshallow, younger sands that are clean and of high permeability.This, together with the advances made in horizontal drilling,completion and sand control technology, has allowed operators

to achieve production levels that have made commercialdevelopments possible. Harding and Gryphon wereoutstanding achievements when they came onstream. At thetime Harding had one of the lowest development costs perbarrel in the UKCS3. The Captain field, which came onstreamin March 1997, set another milestone by demonstrating theattractiveness of developing even more viscous fields.

Until recently, very active appraisal work on fields with yetmore viscous oils, Mariner (65 and 540 cp) and Bressay (1000cp) has been ongoing. As with other appraisal activity, work onthese fields has slowed down at present. However, there issome degree of optimism shown by the industry at large, asregards the longer term future of UKCS heavy oils. This hasbeen apparent in the interest shown in licence blocks in theheavy oil areas in the UKCS.

The industry is continuing to look for innovative andaggressive ideas for driving down costs (finding, developmentand operating costs on a per barrel basis). This has to beachieved within the context of the new environmentalregulations that are being put in place. A general, industry led,cost reduction initiative, termed CRINE (Cost ReductionInitiative for the New Era) has been going on for a few years.This has resulted in about a 30% reduction in costs of oil andgas projects. CRINE has been superseded by CRINENETWORK, which is committed to making the UK oilindustry competitive anywhere in the world. Heavy oildevelopments should have the scope for even more innovativeideas. Some areas to focus on, to reduce capex requirements,would be the following:• Improved reliability of sand control equipment, ESP life and

so on.• Reduction of produced water volumes to surface - well type,

location, designer wells, smart well completions, downholeseparation, polymers to reduce mobility ratio, and so on.

• Facilities sharing - joint development of more than one fieldmay prove economic, where the development of eachindividual field is uneconomic. For example, the mainprocessing facilities could be located at the field with theheaviest oil, while the less viscous crudes can be pumped toit by pipeline (possibly with some partial subsea processing).Other facilities such as drilling support, injection water,electrical power, fuel gas, operational logistics and so on, canbe shared.

Finally, the marketability and future demand for thesecrudes needs to be thoroughly researched. In general, theseheavy crudes cannot be sold on the spot market. They are solddirect to buyers, usually at a small price discount from theBrent marker price. UKCS heavy oils are generally low inSulphur, but some may be higher in acidity. Higher aciditycrudes may be used for blending with other crudes, paying aprice penalty. The economics of removal of the acidity, torestore the value of the crude, could also be looked at. Some ofthe heavy crudes may be sold as "lube oil" crudes, or as fueloil bypassing any refining stage. In such cases the crudes mayeven command a small premium.


Conclusions1. Significant momentum has been generated in developing

UKCS heavy oils, and this is reflected by the interest shown byoperating companies in heavy oil license blocks.

2. Continued cost reduction and technology innovation willhelp to maintain this level of activity.

3. The excellent quality of many of the reservoirs partlyoffsets the higher viscosity of the oil. Horizontal wells providethe means to manage the effects of water and gas coning, andsufficient well productivity in the lower productivity fields.

4. It is important to research the long term market for thesecrudes to maximise the price achieved with respect to markercrudes.

5. Heavy oils represent a significant potential resource baseon the UKCS, with around 10 billion STB in place. Therecovery factor will depend on the development schemes used.Assuming an average recovery factor in the range 20 to 40%shows that there are approximately 1.5 to 3 billion STB to beproduced over and above that from existing UKCS heavy oildevelopments.

NomenclatureBo = oil formation volume factorh = reservoir thickness, ftk =permeability, md

J* = productivity index, bbl.cp/(day.psi.md.ft)Q = production rate, bbl/dayT = temperature, oF

∆p = pressure drawdown, psire = radius of well drainage area, ftrw = radius of well, ftµo = reservoir viscosity, cpµod = dead oil viscosity, cp

Subscriptsh = horizontalv = vertical

AcknowledgementsWe thank the DTI for permission to publish this paper and forproviding the resources to prepare it; members of the DTIField Development teams and Northern North Sea SectorExploration/Appraisal team for contributing to the sections onheavy oil resources and case histories; David Element of AEATechnology for preparing the data contained in Figures 3 to 5;and the operators and partners who gave permission forinformation to be included in the case history sections and theassociated figures. We also thank Mervyn Grist and MarkSimpson of the DTI and Terry Fishlock of AEA Technologyfor their helpful review comments on the paper.

References1. Bennison T.: “Prediction of Heavy Oil Viscosity,” paper

presented at IBC conference on Heavy Oil Field Development,London, UK, Dec. 2-3 1998.

2. Renard, G.I. and Dupuy, J.M.: “Influence of Formation Damageon the Flow Efficiency of Horizontal Wells,” paper SPE 19414,presented at Formation Damage Control Symposium, Lafayette,Louisiana, Feb. 22-23 1990.

3. Smith, S.L.: “The Harding Field: A Low Development Cost perBarrel Concept Becomes a Reality,” paper SPE 30384,presented at the Offshore Europe Conference, Aberdeen, Sept.5-8 1995.

4. Smith, P.J., Hendry, D.J. and Crowther, A.R.: “TheQuantification and Management of Uncertainty in Reserves,”paper SPE 26056 presented at the Western Regional Meeting,Ankorage, Alaska, May 26-28 1993.

5. Moralee, T.A., McDonald, B.J. and Phillips, D.R.: “ReservoirEngineering of a Geologically Complex North SeaEocene/Palaeocene Reservoir With Highly UnfavourableMobility Ratio and Gas/Water Coning,” paper SPE 22916,presented at the 66th Annual Technical Conference andExhibition, Oct. 6-9, 1991.

6. Brown, G. and Goodson, R.J.: “Early Operating Experience of aMinimum Facilities Platform Designed to Process 20 ºAPIEocene Crude Oil,” paper OTC 7469, presented at the 26thAnnual OTC, Houston, Texas, May 2-5 1994.

7. Alexander, K., Winton S. and Price-Smith, C.: “Alba FieldCased Hole Horizontal Gravel Pack - A Team Approach toDesign,” paper SPE 30315 presented at the InternationalMeeting on Petroleum Engineering, Beijing, China, Nov. 14-171995.

8. Etebar, S.: “Captain Innovative Development Approach,” paperSPE 30369, presented at the Offshore Europe Conference,Aberdeen, Sept. 5-8 1995.

9. Pallant, M., Cohen, D.J. and Lach, J.R.:“Reservoir EngineeringAspects of the Captain Extended Well Test Appraisal Program,”paper SPE 30437, presented at the Offshore Europe Conference,Aberdeen, UK, Sept. 5-8 1995.

10. Lach, J.R. and Osterloh, W.T.: “Viscous Oil RecoveryProcesses: Captain Field,” presented at the DTI IOR BestPractice Conference, London, Nov. 9 1995

11. Falt, U., Guerin, G., Retail, P. and Evans, M.: “Clair Discovery:Evaluation of Natural Fracturation in a Horizontal Well Drilledin the Basement and Producing From Overlying Sediments,”paper 25016, presented at the European Petroleum Conference,Cannes, France, Nov. 16-18 1992.

12. Goodyear, S.G., Mead, B.J. and Woods, C.L.: “A NovelRecovery Mechanism for Polymer Flooding in GravityDominated Viscous-Oil Reservoirs,” SPERE (November 1995)259.

13. Element, D.J., Goodyear, S.G., Green J.A., Johnstone, J. andSargent, N.C.: “Relative Permeability Analysis for GravityDrainage of Viscous Oils,” paper presented at the IEACollaborative Project on Enhanced Oil Recovery, 19thInternational Workshop, Carmel, California, October 1998.

14. Goodyear, S.G., Reynolds, C.B. and Woods, C.L.: “ Hot WaterFlooding for High Permeability Viscous Oil Fields,” paper SPE35373, presented at 10th SPE/DOE Symposium on ImprovedOil Recovery, Tulsa, Oklahoma, April 21-24 1996

15. Goodyear, S.G. and Townsley, P.H.: “The Influence ofReservoir Heterogeneity on Hot Water Flooding IOR,” paper


presented at the IEA Collaborative Project on Enhanced OilRecovery, 17th International Workshop, Sydney, Australia, 30September to 1 October 1996.

16. Woods, C.L., Goodyear, S.G., Jones, P.I.R and Reynolds, C.B.:“The Impact of Injection Water Temperature on Recovery fromViscous Oil Reservoirs,” presented at 8th European Symposiumon IOR, Vienna, May 1995

Conversion Factorsacre x 4.046 873 E+03 = m2

oAPI 141.5/(131.5+ oAPI) = g/cm3

bbl x 1.589 874 E-01 = m3

cp x 10 E-03 = Pa.soF (oF-32)/1.8 = oCft x 3.048* E-01 = m

psi x 6.894 757 E+00 = kPa*Conversion factor is exact

TABLE 1 - UKCS HEAVY OIL ACCUMULATIONSFields in production

Field Operator DiscoveryDate

APIo Age Depth(ft)

Permeability(md)

ReservoirTemp (oF)

Viscosity(cp)

STOIIP(MMSTB)

Alba Chevron 1984 20 Mid Eocene 6500 3000 165 7 >500Captain Texaco 1977 19 Lower

Cretaceous2900 7000 87 88 956

Gryphon KMcGee 1987 21 Eocene 5700 10000 140 6 207

Harding BP 1988 19-21 Eocene 5700 10000 140 5 -10 >322

Gannet E Shell 1982 20 Palaeocene 5700 870 175 20 132

Total >2100Fields under appraisal

Mariner(M)

Texaco 1981 14 Palaeocene 4800 5000 116 65

Mariner(H)

Texaco 1981 12 UpperPalaeocene

4200 3000 100 540

Bressay Chevron 1976 11-12 UpperPalaeocene

3500 10000 93 1000

Clair(Core)

BP andothers

1977 25 Carbonifer./ Devonian

6100 20 - 50 155 3-8

Total 2700Total of other discoveries 2400

Total of prospects 2000Total Developed+Discoveries+Prospects >9200


TABLE 2 - OIL CHARACTERISTICS/QUALITYField APIo Sulphur

(wt %)TAN

(mgKOH/g)Wax

(wt%)Pour point

(oF)Asphaltene

(wt%)Alba 20 1.3 1.6 1.0 -13 1.0Captain 19 0.7 2.5 trace -26 0.3Gryphon 21 0.4 4.5 0.1 -45 0.1Harding C 19 0.6 3.1 0.7 -17 0.35Harding S 21 0.5 2.8 <0.1 -44 0.2Gannet E 20 0.8 1.2 2.5 10 0.85Mariner M) 14 1.1 4.1 nil 20 1.9Mariner (H) 12 1.4 5.5 nil 1.6Bressay 11-12 0.8 8.0 not measureable 45 1.2Clair 25 0.5 1.2 4.5 -4 0.85


Figure 1: - Major structural elements in the Central and Northern North Sea and location of major heavy oil accumulations in the UKCScurrently under development or appraisal.

MARINE

GANNET

ALBA

CAPTAI

BRESSA

GRYPHON&

CLAIR

EastShetlandPlatform

Moray Firth

West ofShetland

Halibut

CentralNorthSea

FladenGround

Spur

Mid NorthSea High

Central

Grab

NorthernNorthSea

VikingGraben

Sedimentary

High

Heavy

Othe

FIELD

Orkney Islands

Shetland

SCOTLAND


Figure 2: - Lower Tertiary stratigraphy of Northern North Sea.

10 15 20 25

°API

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

De

pth

(ft

)

Figure 3: - Reservoir depth vs. API gravity for North Seadiscoveries with API gravity less than 25o from the ShetlandPlatform and Fladen Ground Spur.

1

10

100

1,000

10,000

10 12 14 16 18 20 22 24 26

°API

De

ad O

il V

isco

sity

(cp

)

Figure 4: - Estimated viscosities of dead oil at reservoirtemperature as a function of degrees API


Captain

Mariner (M)

Mariner (H)

Bressay

0.1

1

10

100

1000

10,000 100,000 1,000,000 10,000,000

Permeability Thickness (md.ft)

Oil

Vis

co

sity

(cp

)

50,000md.ft/cp

5,000 md.ft/cp Alba, Harding, Gryphon

Light Oil Reservoirs

Gannet 'E'

Figure 5: - Viscosity plotted against the permeability thickness product for heavy oil fields and representative light oil fields, showing fieldswith equivalent productivity.

0

0.005

0.01

0.015

0.02

0.025

0.03

0 1000 2000 3000 4000 5000 6000

Horizontal Well Length (ft)

Pro

du

ctiv

ity

Ind

ex J

* (b

bl.

cp/(

day

.psi

.md

.ft)

) Horizontal well, h = 50ft

Horizontal well, h = 100ft



Vertical well

Figure 6:- Productivity index for vertical and horizontal wells


Figure 7: Harding field oil isochore and development wells Figure 8: - Harding field: schematic cross-sections throughCentral and South accumulations

Figure 9: - Captain field: oil accumulation map showing development areas A and B


Figure 10: - Captain field: cross-section showing trajectory of typical area A development well

Figure 11: - Mariner field: type log.


Gas cap

Figure 12: - Bressay field: oil isochore

eor - the development of heavy oil fields in the u.k. continental

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